1. Field of the Invention
This invention relates in general to logging tools for detecting parameters of fluid flows, and in particular to a logging tool for detecting flow parameters of multiphase fluid flow.
2. Description of the Prior Art
Prior art production logging tools have been utilized for detecting flow velocities of multiphase fluid flows within oil and gas wells. Prior art production logging tools have included spinner type flowmeters which rotate when immersed within a flowstream. Spinner type flowmeters include fullbore flowmeters and deflector flowmeters. Fullbore flowmeters typically detect fluid flow within a central region of cross-section of a well. Deflector flowmeters typically restrict the fluid flow through part of a cross-section of the well, causing the fluid flow to pass through an unrestricted region of the well in which the flow is detected. One type of deflector flowmeter restricts the flow in a central region of the well, causing the flow to pass into an annulus and by a plurality of spinner type of flowmeters which detect the fluid flow. Deflector types of flowmeters detect fluid flows in either a central, or an outer annulus region of a well cross-section.
Prior art production logging tools also usually include other types of tools which detect downhole densities, pressures and fluid holdup of production fluids. Flow data measured with prior art flowmeters is usually combined with data from these other types of tools, and then a total flow rate of various components of the multiphase fluid flow through the well is computed. The computed flow values are typically approximated by assuming that the multiphase fluid flow has a velocity profile of a particular shape. Typically, the velocity profile shape is assumed to be uniform to simplify the calculations. However, all wells are deviated to some extent. This usually causes the actual velocity profile shapes of fluid flow within the wells to differ from that used for the calculations.
In highly deviated wells and horizonal wells the fluid flow may become stratified across a cross-sectional area of the well. This may result in prior art fullbore spinner type flowmeters detecting only a small portion of the stratified flow, such as only one phase, and not the other portions of the flow of produced fluids. Very often, locating an entry point for only a small portion of the multiphase fluid flow is desired. If the small portion of the fluid flow is located along the outer periphery of the cross-section of the well, it may not be detected by a full bore flowmeter. Further, the relative proportion of the small portion of the fluid flow with respect to the total fluid flow may be so small that it will not be detected by either a full bore or deflector types of flowmeters, since they typically average readings for the total flow of the multiphase fluid flow through wells.
Different types of flow patterns may be present in multiphase fluid flows, both within vertical flow and horizontal flow. These different types of flow patterns further complicate the problem of determining the flow velocities of multiphase fluid flows. In horizontal flow, very often bubble flow and elongated bubble flow will occur. Additionally, stratified flow, wave flow, slug flow, annular and annular mist flow and dispersed froth flow may occur depending on the different flow parameters and flow velocities encountered. Vertical flow patterns may also include bubble flow, froth flow, annular, annular mist flow and slug flow. These different flow patterns occur depending on the velocities, the cross-sectional diameter, and other such parameters affecting flow rate. Typically, the volumetric proportions which occur at downhole well conditions are much different than those that occur further uphole, and those that occur on the surface. Differences between uphole and downhole volumetric proportions of multiphase fluid flows which include a gas phase are often affected by the amount of gas which stays in solution uphole as compared to the amount of gas which stays in solution downhole, and other such similar type of phenomenon. These other types of flow patterns decrease the accuracy of these approximations and assumptions, further decreasing the reliability of flow velocity flow determinations made with prior art production logging tools.
Typically, different densities, frictional parameters and different phases of different constituents of segregated multiphase fluid flow result in the different constituents having different flow velocities. For example, in a segregated, multiphase flow in a producing well having flow constituents which consist of oil, gas and water, the gas phase may flow faster than the oil phase, which may flow faster than a water phase. In fact, in some sections of wells having multiple zones of production, one phase may flow in an opposite direction within the well to that of a net flow of fluids. When annular type of flow segregation occurs, such as with slug, annular mist and froth flow, only the flow occurring within the central portion of a cross-sectional area of a well is detected. Prior art production logging tools typically only measure flow parameters of multiphase fluid flows within a single particular limited region of a cross-sectional area of a well, requiring approximations and assumptions of flow characteristics. The flow occurring around an outer circumference of the well is very often not detected by prior art well logging tools, such as either fullbore spinner or deflector types of flow meters discussed above.